1. Field of the Invention
The present invention relates to techniques for optimizing oilfield operations relating to subterranean formations having reservoirs therein. More particularly, the invention relates to techniques for optimizing oilfield operations involving an analysis of reservoir operations, and their impact on such oilfield operations with deference to physical constraints present in any part of the petroleum production and fluid injection systems and with deference to reservoir and financial uncertainty.
2. Background of the Related Art
Oilfield operations, such as surveying, drilling, wireline testing, completions, simulation, planning and oilfield analysis, are typically performed to locate and gather valuable downhole fluids. Various aspects of the oilfield and its related operations are shown in FIGS. 1A-1D. As shown in FIG. 1A, surveys are often performed using acquisition methodologies, such as seismic scanners to generate maps of underground structures. These structures are often analyzed to determine the presence of subterranean assets, such as valuable fluids or minerals. This information is used to assess the underground structures and locate the formations containing the desired subterranean assets. Data collected from the acquisition methodologies may be evaluated and analyzed to determine whether such valuable items are present and if they are reasonably accessible.
As shown in FIG. 1B-1D, one or more wellsites may be positioned along the underground structures to gather valuable fluids from the subterranean reservoirs. The wellsites are provided with tools capable of locating and removing hydrocarbons from the subterranean reservoirs. As shown in FIG. 1B, drilling tools are typically advanced from the oil rigs and into the earth along a given path to locate the valuable downhole fluids. During the drilling operation, the drilling tool may perform downhole measurements to investigate downhole conditions. In some cases, as shown in FIG. 1C, the drilling tool is removed and a wireline tool is deployed into the wellbore to perform additional downhole testing.
After the drilling operation is complete, the well may then be prepared for production. As shown in FIG. 1D, wellbore completions equipment is deployed into the wellbore to complete the well in preparation for the production of fluid therethrough. Fluid is then drawn from downhole reservoirs, into the wellbore and flows to the surface. Production facilities are positioned at surface locations to collect the hydrocarbons from the wellsite(s). Fluid drawn from the subterranean reservoir(s) passes to the production facilities via transport mechanisms, such as tubing. Various equipment may be positioned about the oilfield to monitor oilfield parameters and/or to manipulate the oilfield operations.
During the oilfield operations, data is typically collected for analysis and/or monitoring of the oilfield operations. Such data may include, for example, subterranean formation, equipment, historical and/or other data. Data concerning the subterranean formation is collected using a variety of sources. Such formation data may be static or dynamic. Static data relates to, for example, formation structure and geological stratigraphy that define the geological structure of the subterranean formation. Dynamic data relates to, for example, fluids flowing through the geologic structures of the subterranean formation over time. Such static and/or dynamic data may be collected to learn more about the formations and the valuable assets contained therein.
Sources used to collect static data may be seismic tools, such as a seismic truck that sends compression waves into the earth as shown in FIG. 1A. These waves are measured to characterize changes in the density of the geological structure at different depths. This information may be used to generate basic structural maps of the subterranean formation. Other static measurements may be gathered using core sampling and well logging techniques. Core samples may be used to take physical specimens of the formation at various depths as shown in FIG. 1B. Well logging typically involves deployment of a downhole tool into the wellbore to collect various downhole measurements, such as density, resistivity, etc., at various depths. Such well logging may be performed using, for example, the drilling tool of FIG. 1B and/or the wireline tool of FIG. 1C. Once the well is formed and completed, fluid flows to the surface using production tubing as shown in FIG. 1D. As fluid passes to the surface, various dynamic measurements, such as fluid flow rates, pressure, and composition may be monitored. These parameters may be used to determine various characteristics of the subterranean formation.
Sensors may be positioned about the oilfield to collect data relating to various oilfield operations. For example, sensors in the drilling equipment may monitor drilling conditions, sensors in the wellbore may monitor fluid composition, sensors located along the flow path may monitor flow rates, and sensors at the processing facility may monitor fluids collected. Other sensors may be provided to monitor downhole, surface, equipment or other conditions. The monitored data is often used to make decisions at various locations of the oilfield at various times. Data collected by these sensors may be further analyzed and processed. Data may be collected and used for current or future operations. When used for future operations at the same or other locations, such data may sometimes be referred to as historical data.
The processed data may be used to predict downhole conditions, and make decisions concerning oilfield operations. Such decisions may involve well planning, well targeting, well completions, operating levels, production rates and other operations and/or conditions. Often this information is used to determine when to drill new wells, re-complete existing wells, or alter wellbore production.
Data from one or more wellbores may be analyzed to plan or predict various outcomes at a given wellbore. In some cases, the data from neighboring wellbores or wellbores with similar conditions or equipment may be used to predict how a well will perform. There are usually a large number of variables and large quantities of data to consider in analyzing oilfield operations. It is, therefore, often useful to model the behavior of the oilfield operation to determine the desired course of action. During the ongoing operations, the operating conditions may need adjustment as conditions change and new information is received.
Techniques have been developed to model the behavior of various aspects of the oilfield operations, such as geological structures, downhole reservoirs, wellbores, surface facilities as well as other portions of the oilfield operation. For example, U.S. Pat. No. 6,980,940 to Gurpinar discloses integrated reservoir optimization involving the assimilation of diverse data to optimize overall performance of a reservoir. In another example, WO2004/049216 to Ghorayeb discloses an integrated modeling solution for coupling multiple reservoir simulations and surface facility networks. Other examples of these modeling techniques are shown in U.S. Pat. No 5,992,519, WO1999/064896, WO2005/122001, U.S. Pat. No. 6,313,837, US2003/0216897, US2003/0132934, US2005/0149307, US2006/0197759, US2004/0220846, and Ser. No. 10/586,283.
Techniques have also been developed to predict and/or plan certain oilfield operations, such as miscible water alternating gas (MWAG) injection operation. In an oilfield, initial production of the hydrocarbons is accomplished by “primary recovery” techniques wherein only the natural forces present in the reservoir are used to produce the hydrocarbons. However, upon depletion of these natural forces and the termination of primary recovery, a large portion of the hydrocarbons remains trapped within the reservoir. Also, many reservoirs lack sufficient natural forces to be produced by primary methods from the very beginning.
Recognition of these facts has led to the development and use of many enhanced oil recovery (EOR) techniques. Most of these techniques involve injection of at least one fluid into the reservoir to force hydrocarbons towards and into a production well. It is important that the fluid be injected carefully so that it forces the hydrocarbons toward the production well but does not prematurely reach the production well before all or most of the hydrocarbons have been produced.
Generally, once the fluid reaches the production well, production is adversely affected as the injected fluids are not generally sellable products and in some cases can be difficult to separate from the produced oil. Over the years, many have attempted to calculate the optimal pumping rates for injector wells and production wells to extract the most hydrocarbons from a reservoir. There is considerable uncertainty in a reservoir as to its geometry and geological parameters (e.g., porosity, rock permeabilities, etc.). In addition, the market value of hydrocarbons can vary dramatically and so financial factors may be important in determining how production should proceed to obtain the maximum value from the reservoir. Examples of techniques for modeling and/or planning MWAG injection operation are provided in U.S. Pat. No. 6,775,578.
Techniques have also been developed for performing reservoir simulation operations. See, for example, U.S. Pat. No. 6,230,101, U.S. Pat. No. 6,018,497, U.S. Pat. No. 6,078,869, GB2336008, U.S. Pat. No. 6,106,561, US2006/0184329, U.S. Pat. No. 7,164,990. Some simulation techniques involve the use of coupled simulations as described, for example, in Publication No. US2006/0129366.
Techniques have also been developed for performing optimization of reservoir operations with the intent to most economically produce the field. See, for example, U.S. Pat. No. 6,775,578.
Despite the development and advancement of reservoir simulation techniques in oilfield operations, there remains a need to provide techniques capable of modeling and implementing operations based on a complex analysis of a wide variety of parameters affecting oilfield operations. It is desirable that such a complex analysis of oilfield parameters gathered throughout the oilfield and their impact on the oilfield operations be performed considering reservoir uncertainty and/or financial uncertainty. It is further desirable that such techniques for modeling and/or optimizing oilfield operations be capable of one of more of the following, among others: optimizing objective functions such as net present value (NPV) of oilfield production based on levels of risk associated with the reservoir uncertainty and/or financial uncertainty, modeling the objective function based on estimated performance by performing concurrent simulation, selectively modeling oilfield operations based on more than one simulator; selectively merging data and/or outputs of more than one simulator; selectively merging data and/or outputs of simulators of one or more wellsites and/or oilfields; selectively linking a wide variety of simulators of like and/or different configurations; selectively linking simulators having similar and/or different applications and/or data models; selectively linking simulators of different members of an asset team of an oilfield; and providing coupling mechanisms capable of selectively linking simulators in a desired configuration.